Recovering hydrocarbons such as oil and gas from high permeability reservoirs is well understood. However, recovery of hydrocarbon resources from low-permeability reservoirs is more difficult and less well understood (See Boyer, C., et al., Producing Gas from Its Source. Oilfield Review, 2006. Autumn 2006: p. 36-49.). Consequently, operators have until recently tended to bypass low permeability reservoirs such as shales in favor of more conventional reservoirs such as sandstones and carbonates.
In order to develop methods to efficiently recover gas from an underground reservoir, it is very useful to gain a good understanding of the chemical nature of the formation. For example, a shale reservoir typically includes a matrix of small pores and may also contain naturally occurring fractures/fissures (natural fractures). These natural fractures are most usually randomly occurring on the overall reservoir scale. The natural fractures can be open (have pore volume) under in-situ reservoir conditions or open but filled in with material (have very little or no pore volume) later in geologic time; for example, calcite (CaCO3). These fractures can also be in a closed-state (no pore volume) due to in-situ stress changes over time. Natural fractures in any or all of these states may exist in the same reservoir. For more complete understanding of the occurrence, properties, behavior, etc. of naturally fractured reservoirs in general, one may review the following references: Nelson, Ronald A., Geologic Analysis of Naturally Fractured Reservoirs (2nd Edition), Elsevier, and Aguilera, Roberto, Naturally Fractured Reservoirs, PennWell Publishing. The permeability of the shale pore matrix is typically quite low, e.g., in the less than one millidarcy range. In a shale gas reservoir, this presents a problem because the pore matrix contains most of the hydrocarbons. Since the low permeability of the pore matrix restricts fluid movement, it would be useful to understand how to prompt mass transfer of hydrocarbons from the pore matrix to the fracture network.
Tight sandstone reservoirs have dominated the hydraulic fracturing market in North America for years, and due to their relatively simple lithology (when compared to gas shales) they have been assumed to be water wet for most stimulation fluid design programs. Most slickwater stimulation treatments were originally formulated for these tight sandstone reservoirs, and to a great extent were adapted “as is” to the gas shale market as it grew. However, due to the wide variation in mineralogy and lithology of kerogen rich shales, the variation in wetting characteristics from reservoir-to-reservoir, and formation-to-formation, has become a major issue. Some reservoirs with high total organic carbon (TOC) values appear to be predominantly if not completely oil-wet. Other shale-like formations, correctly referred to as mudstones or siltstones, appear to be of mixed wettability. Furthermore, any exploitation of the shale reserves requires injection of large quantities of water-based fluids during hydraulic fracturing treatments—and most of this water is not recovered.
Damage to the fracture conductivity and damage to the near-fracture matrix permeability caused by residual water is a major concern. It is hypothesized by many that fracture cleanup and the formation of water blocks in the matrix will be determined by the extent to which the fracturing fluid wets the formation. The extent to which a fluid wets the surfaces of pores will determine how the fluid penetrates the porous medium by imbibition. The extent to which a fluid wets the surface of the fracture face will strongly influence how effectively gas can displace residual water in the fracture network—and may be a key factor in determining the required fracture conductivity. The contact angle is a quantitative thermodynamic measure of the relative wettability of a substrate with respect to two fluids brought into contact with it.
There is a distinct difference between the advancing, the static and the receding contact angles. While the advancing contact angle describes the dynamic contact angle of a fluid invading a surface, the receding contact angle describes the contact angle of a fluid that is displaced from the surface. Generally, the advancing contact angle is associated with imbibition, the process where a wetting fluid spontaneously displaces a non-wetting fluid from a porous medium. For example, Hirasaki, G. and Zhang, D., “Surface Chemistry of Oil Recovery From Fractured, Oil-Wet Carbonate Formation”, SPE 80988 (2003) describe capillary pressure and the effects of surface chemistry on imbibition for oil recovery. On the other hand, the receding contact angle is associated with drainage, the process where a wetting fluid is displaced from a porous medium by a non-wetting fluid. So the advancing contact angle describes the interaction between the fluid and the surface when the fluid flows into the rock and the receding contact angle describes the flow of fluid out of the rock. There can be a large hysteresis between the two dynamic contact angles with the static contact angle, describing the angle formed by a static fluid on a surface, lying in-between but not necessarily in the middle.
When the advancing contact angle is known, a prediction can be made as to how fast a fluid will be imbibed into a certain rock matrix or into a microfracture. With this information, the amount of fluid that is imbibed into the rock in a given time can be calculated. The receding contact angle on the other hand can be used to calculate the drainage of a wetting fluid from a rock for a given pressure applied to a non-wetting fluid. It is not only important to know how fast a fluid is imbibed into a rock, it is equally important to know how easily it comes back out. A large amount of water imbibed into the formation during a treatment may not be a problem when it is quickly driven out of the pore space after the treatment is finished. Contrary, a small amount of imbibed fluid can cause severe water blocks if it cannot be retrieved from the rock matrix. The receding contact angle can also be used to determine how quickly a treatment fluid in the fracture network is displaced by hydrocarbons when the well is put on production. A high receding contact angle indicates easy displacement of the treating fluid by the hydrocarbon from the formation. In order to increase the receding contact angle of the treatment fluid on the fracture surface, surface active additives can be used. The effectiveness of an additive can be measured in a drainage test with rock material that was treated with the respective additive.
Knowing the receding contact angle, treatment fluids could be designed that contain optimum amounts of the right additive for a given rock. For example with hydrophilic surfaces that like to be wetted with water, an additive that makes the surface more hydrophobic may be used so water can be easily expelled or is not taken up in the first place.